1. Field of the Invention
This invention relates to an oil well completion tool that is adapted to be interposed in a multiple-section tubing string within an oil well casing, most usually above another oil well tool, such as a packer. The completion tool allows the tubing string to be blocked, for example, in order to allow setting of a packer or the like, and to thereafter be fully opened for production from the well.
2. Description of the Prior Art
Typically when oil or gas wells are drilled in hydrocarbon-bearing formations, the bore hole is thereafter isolated from the surrounding formation by a string of interconnected, relatively large diameter pipe sections, generally referred to as a well casing. The casing sections may, for example, be about 5 inches to about 9 inches in diameter. Cement is most often placed around the casing throughout its length to provide a barrier between the outside of the casing and the inside of the bore hole of the well. The cement acts to prevent communication of fluids and gases under pressure from one underground formation to the next.
A tubing string fabricated from smaller diameter individual pipe sections interconnected end-to-end is commonly run into the well within the casing. During completion of a typical cased well, a tool such as a packer may be provided on the end of the tubing string to isolate the area called an annulus between the inside of the casing and the outside of the tubing string. There are many types of oil well packers in use, with elastomeric sleeves or bladders engageable with the interface of the casing being expanded and “set” either mechanically, by inflation, hydraulically, or using a wire line set. Mechanical packers are generally actuated by rotation of the string which compresses the sleeves to bring the outer surfaces thereof into sealing engagement with the casing.
Hydraulic packers offer many installation and operating advantages, particularly where the well casing has a number of bends and therefore is not essentially straight throughout its length, or requires installation in a horizontal well bore, making a mechanical packer impractical. In the case of a hydraulic packer, it is necessary to provide a plug within the casing below the packer to offer resistance to the hydraulic pressure required for setting of the packer bladders. Once the packer is set, the plug must be opened fully in order for oil production to be initiated. Hydraulic packers are only one example of downhole tools that require pressurized hydraulic fluid to function.
In well stimulation operations, it is common to “surge” the formation in order to clean debris from the formation and improve the flow of hydrocarbons. Surging is accomplished by reducing the pressure inside of the tubing string by an amount below that of the formation pressure and allowing this difference in pressure to equalize very rapidly. Another example of well stimulation involves increasing the fluid pressure within a tubing string to a value substantially above the formation pressure. When the pressure in the tubing string is released rapidly as compared with the formation pressure, fractures in the formation are created such that hydrocarbons can be produced without traveling through damaged rock from well drilling and completion operations.
In these examples, as is the case with other exemplary completion processes, it is advantageous that immediately after functioning as a tool is initiated or stimulation is undertaken, the plug be completely removed from the flow path of the well.
The prior art is replete with exemplary tools for assisting in setting of packers and similar well annulus isolation devices. Many of these tools utilize a plug for temporarily blocking a tubing string in order that hydraulic pressure on a packer or the like may be applied to the tool. Certain plugs have been run on a wire line and set in place. After the pressure operation, the line is retrieved to pull the plug to the surface. This type of operation has been found to be time-consuming and presents associated risks with well intervention.
Other well casing isolation tools have been provided with tubing string blocking devices such as glass or ceramic plugs. These plugs have been opened either by dropping a bar from the surface, which causes plug failure, or overpressuring the plug to failure. Many unsolved problems and safety concerns have arisen by use of these types of plugs, in that the material is frangible and thus subject to micro-fractures resulting from rough handling at the well surface, improper assembly in the tool, or tolerance issues that greatly reduce their pressure ratings, causing unpredictable plug failure.
A pressure responsive rupture valve, especially useful for surging an oil well, in U.S. Pat. No. 3,779,263, employs a tubular cutting sleeve shifted by a pressure responsive tubular piston. The main valve passage communicates directly with the chamber of the piston. Upon pressurization of the piston chamber by fluid introduced into the valve passage, the piston-actuated cutting sleeve is shifted toward a rupture disc normally blocking the passage through the valve. The disc is deeply scored by a series of radially oriented score lines. When the multi-angular cutting edge of the cutting sleeve engages the disc, it breaks up as a series of individual petals that fold outwardly toward the wall structure of the valve.
The valve of U.S. Pat. No. 4,609,005 relies upon a tubular cutting mandrel for severing a portion of a disc normally blocking the passage through the valve housing while leaving a narrow uncut section by virtue of an elongated slot in the operating edge of the cutting mandrel. As is apparent from FIG. 2 of the drawings of the '005 patent, the mandrel, in its fully actuated position, cannot assure that a required drift diameter is maintained through the opened valve, in part because of the spacing between the mandrel and the adjacent valve housing wall.
A well bore annulus pressure responsive surge tool is described in U.S. Pat. No. 4,658,902. A tubular cutter mandrel carried within the housing of the tool and shiftable by a separate power mandrel is operable to engage and cut a C-shaped section out of a frangible disc normally blocking the passage through the tool. The cutter mandrel has a longitudinally-extending slot, which leaves a flap portion of the disc uncut. The severed section of the disc, as well as the flap portion, are said to be deflected laterally by the mandrel and retained between the outer surface of the mandrel and the inner surface of the housing. One or more pins must be sheared before the power mandrel can effect shifting of the cutter mandrel toward the disc. Because of the provision of the elongated slot in the cutter mandrel, that mandrel must be shifted through a displacement significantly greater than the length of the slot in the mandrel. In order to accomplish this extended path of travel of the mandrel, two-stage mandrel structure is required, which, along with the pins controlling release of the mandrels, thus adds to the complexity of the mechanism and its attendant cost, and at the expense of overall reliability.
The plug for an oil or gas well bore hole in PCT application PCT/GB97/02043 is described as being a replacement for conventional bursting type plugs that, when pressurized above a certain level, burst in order to open a tubing string. A section of these earlier plugs can break free from the tubing string, thereby resulting in a piece of unwanted equipment at the bottom of the well causing problems at a later time. The plug of the '043 application is made up of a threaded box end, a threaded pin end, an upper tubular body member, and a lower tubular body member. A steel barrier plate, machined from the lower body member, extends across a central bore of the tubing. A cutter having a tapered cutting blade is secured to the lower body member by a shear pin. The cutter is shifted by a movable piston sleeve temporarily held in a retracted position in the lower body member by locking dogs and a slotted lock sleeve. By cycling the pressure within the tubing, the piston sleeve is moved up and down against the action of a spring until a slide bolt enters a selected position in the slotted sleeve. This results in release of the locking dogs, permitting the sleeve to move downward into engagement with the cutter, effecting shearing of the shear pin and allowing the cutter to impact against the barrier plate. Because only a part of the plate is severed, the cut segment thereof is deflected outwardly by the cutter into a recessed section in the box end. This tool is very large and can be used only in large diameter casings. The functional reliability of this very complicated and expensive mechanism under the difficult conditions that exist at the extreme depths of well bore holes is inherently problematical, and renders the unit unsuited for a majority of wells.
A tubing string isolation tool employing a frangible glass disc is described in U.S. Pat. No. RE39,209. The presence of the glass disc permits well fluid from the ground surface to be introduced into the tubing string at an increased pressure to establish a hydrostatic load allowing a packer or any other ancillary device to be hydraulically set in a conventional manner. When the packer or other ancillary device has been set, and it is desired to recover production fluid from the formation, the pressure of the well fluid in the tubing string is increased, thereby applying a pressurized fluid load against a piston which overcomes shear pin resistance and is moved downwardly with sufficient force to shatter the glass disc. Debris resulting from breakage of the disc can amount to formation of glass chunks that are as much as one-fourth to one-half inch in diameter. Debris of this nature is to be avoided because of a variety of close downhole tolerances. If a metal bar is intended to be used to fracture the glass disc, bends in the tubing string may actually interrupt downward movement of the bar, or impede its movement to an extent that it does not have adequate impact force to break the glass disc.
In U.S. Pat. No. 5,996,696, assigned to the assignee hereof, a rupture disc is used to block the flow path through a tubing string in order to permit testing of the integrity of the tubing string connections. After it has been established that none of the tubing sections are leaking, the discs may be ruptured by application of a predetermined overpressure applied to the disc through the string. All tubing string pipe sections have a required drift diameter for a particular pipe i.d. Although the tubing string integrity testing apparatus of the '696 patent has been found satisfactory for many applications, in certain instances, it has been found that the central section of the disc that is ruptured under overpressure does not completely open and fails to fold against the housing of the apparatus, thereby not providing a required drift diameter through the test apparatus.